Two-phase flow measuring device and method for oil and gas field water corrosion resistance

Abstract

The invention belongs to the technical field of gas field water flow meter measurement, and particularly discloses a two-phase flow measuring device and method resistant to oil and gas field water corrosion. The device is used for measuring gas field water in a pipeline and is matched with a flow totalizer. Comprising a first differential pressure flowmeter used for measuring the mass flow of gas in a pipeline, a second differential pressure flowmeter used for measuring the mass flow of liquid in the pipeline, a temperature sensor used for measuring the temperature of the gas in the pipeline, and a liquid level differential pressure transmitter used for measuring the liquid level in the pipeline. The temperature sensor, the first differential pressure flow meter, the second differential pressure flow meter and the liquid level differential pressure transmitter are respectively connected with the flow totalizer. According to the invention, the problems of gas and liquid two-phase flow measurement, accurate sulfur-containing gas field water measurement and the like can be solved under the condition that gas field water components contain corrosive (especially sulfur-containing components), non-full pipe flow and liquid phase flow velocity.

Description

Technical Field

[0001] This invention relates to the field of gas field water flow meter measurement technology, and more specifically, to a two-phase flow measurement device and method for use in oil and gas field water corrosion resistant applications. Background Technology

[0002] Gas field water is groundwater brought to the surface during natural gas extraction, mainly including associated water from drilling, well testing, well workover, and gas well production. Gas field water has a wide range of sources, numerous types, and complex compositions, exhibiting certain unique characteristics. Analysis of gas field water quality reveals two categories: the first category is high-mineralized gas field water with high organic matter content, exhibiting severely excessive levels of COD, chloride, salt, and anionic surfactants; the second category is high-sulfur gas field water with high organic matter content, exhibiting extremely high sulfide content (approaching 1%) and excessive organic matter.

[0003] Currently, two-phase flow meters used in oil and gas field enterprises are mainly for measuring the water-containing gas phase. The accuracy of measuring the gas phase is relatively high, but the accuracy of measuring the liquid phase carried by the gas phase is low, with a measurement error of up to 20% or more, and they are not corrosion resistant. There is currently no two-phase flow meter specifically for measuring the water-liquid phase in gas fields.

[0004] Currently, the water-liquid phase in oil and gas fields operates in two states. The first is the normal operating state, with a flow rate of 5 m³ / h. 3 The flow rate is approximately / h, the second one is the spraying state, and the flow rate is 60m³ / h. 3 The flow rate is approximately [value missing] / h, once a day or twice a week, depending on the specific production well. There is a significant difference in flow rate between these two operating states; it is necessary to ensure measurement at both low flow rates during normal operation and high flow rates during the initial flow phase. Currently, the gas field water measurement equipment cannot accurately meet the requirements for both states.

[0005] Currently, oil and gas field enterprises primarily use electromagnetic flowmeters and reinjection pump metering for gas field water measurement. However, based on field experience, firstly, both methods are only suitable for measuring the liquid phase alone and cannot measure the small amount of gas phase carried by the liquid phase; secondly, although electromagnetic flowmeters have a high accuracy level, they are easily corroded and damaged by gas field water, and can only provide normal measurement for a short period of time, while reinjection pump metering estimates by multiplying power by time, resulting in low accuracy. In summary, existing gas field water measurement methods suffer from disadvantages such as susceptibility to corrosion from sulfur-containing components, high frequency of damage, inaccurate measurements, and short measurement cycles. Therefore, current oil and gas field water metering methods no longer meet the relevant management requirements of enterprises, directly affecting the formulation and implementation of relevant development plans, as well as the implementation of plans for reducing liquid levels, controlling pollution, and stabilizing production.

[0006] Natural gas extracted from gas fields is a two-phase mixture of gas and liquid. Existing flow meters are designed for measuring single-phase media, which significantly affects measurement accuracy when measuring two-phase gas-liquid mixtures. Considering that the liquid phase in gas fields is primarily water:

[0007] 1. Existing flow meters are difficult to measure two-phase flow (gas and liquid), and can only measure single-phase flow.

[0008] 2. Patent No. CN101738228A discloses a gas-liquid two-phase flow Bitoba flow sensor. Specifically, it discloses that when using the gas-liquid two-phase flow Bitoba flow sensor, a differential pressure transmitter outputs a standard electrical signal of the differential pressure from the Bitoba flow meter, which is then connected to an integrator to calculate the gas velocity of the gas-liquid two-phase fluid. Simultaneously, an electronic level gauge outputs a standard electrical signal of the liquid level in the pipeline being transported by the measured gas-liquid two-phase fluid, which is then sent to the integrator to calculate the gas mass flow rate in the pipeline. This technology is not accurate in measuring gas mass flow rate, and since the gas velocity differs from the liquid velocity, measurement errors are inevitable. Summary of the Invention

[0009] The technical problem to be solved by the present invention is to provide a two-phase flow measuring device and method for oil and gas field water corrosion resistance. The present invention can solve the problems of gas and liquid two-phase flow measurement and accurate measurement of sulfur-containing gas field water under two conditions: gas field water components containing corrosive components (especially sulfur-containing components), non-full pipe flow, and liquid phase flow velocity.

[0010] The solution adopted by this invention to solve the technical problem is:

[0011] A two-phase flow measurement device resistant to water corrosion in oil and gas fields is used for measuring water in oil and gas fields within pipelines and is used in conjunction with a flow totalizer. It includes a differential pressure flowmeter I for measuring the mass flow rate of gas within the pipeline, a differential pressure flowmeter II for measuring the mass flow rate of liquid within the pipeline, a temperature sensor for measuring the temperature of gas within the pipeline, and a differential pressure level transmitter for measuring the liquid level within the pipeline. The temperature sensor, differential pressure flowmeter I, differential pressure flowmeter II, and differential pressure level transmitter are each connected to the flow totalizer.

[0012] In some possible implementations, a gas-liquid splitting device is also included, which is installed inside the pipeline and located in the pipeline inlet section.

[0013] In some possible implementations, a drain outlet is also included on the pipeline for discharging solid impurities separated by the gas-liquid separator.

[0014] In some possible implementations, the differential pressure flow meter one and the differential pressure flow meter two have the same structure, both being deltabar flow meters, and their probes are provided with pressure tapping holes;

[0015] Both differential pressure flowmeter one and differential pressure flowmeter two are provided with a high-pressure chamber and a low-pressure chamber, wherein the high-pressure chamber is located on the flow-facing side of the pipeline and the low-pressure chamber is located on the flow-reverse side of the pipeline.

[0016] The low-pressure sides of differential pressure flowmeter one and differential pressure flowmeter two are respectively connected to the differential pressure transmitter through pressure taps.

[0017] In some possible implementations, the probe of the differential pressure flow meter extends vertically into the pipeline through the top of the pipeline and its end does not contact the liquid.

[0018] The probe of the differential pressure flowmeter II extends vertically into the pipeline through the bottom of the pipeline, and its end does not contact the gas.

[0019] In some possible implementations, when the diameter of the pipeline is A, and A≤DN65; the pressure taps are in a set.

[0020] When DN80≤A≤DN300, there are two sets of pressure taps;

[0021] When A > DN300, there are three sets of pressure taps.

[0022] In some possible implementations, a differential pressure transmitter connected to differential pressure flow meter one, differential pressure flow meter two, differential pressure level transmitter, and flow totalizer is also included.

[0023] The differential pressure transmitter is a multi-parameter transmitter, and its measured differential pressure value is B, where 2Pa≤B≤40kPa.

[0024] A measurement method for a two-phase flow measuring device for oil and gas field water corrosion resistance, as described above, specifically includes the following steps:

[0025] The gas-liquid separator keeps the gas and liquid phases relatively independent, with a clear interface.

[0026] The gas mass flow rate and liquid mass flow rate are calculated based on differential pressure flow meter 1 and differential pressure flow meter 2.

[0027] Calculate the liquid duty cycle C based on the liquid level information provided by the differential pressure level transmitter;

[0028]

[0029] Among them, S 液 S is the cross-sectional area of ​​the liquid. 管 This refers to the cross-sectional area of ​​the pipeline.

[0030] Instantaneous gas flow rate is calculated based on gas mass flow rate and duty cycle;

[0031] Instantaneous flow rate of liquid is calculated based on liquid mass flow rate and duty cycle.

[0032] In some possible implementations, the instantaneous gas flow rate = q ma ×(1-C);

[0033] Instantaneous flow rate of liquid = q mb ×C;

[0034] Where, q ma Let q be the gas mass flow rate. mb This represents the liquid mass flow rate.

[0035] In some possible implementations, the formula for calculating the gas mass flow rate or liquid mass flow rate is...

[0036]

[0037] Where, q m For mass flow rate;

[0038] ζ is the blocking coefficient of the probe;

[0039] ε is the flow expansion coefficient;

[0040] d is the inner diameter of the pipe;

[0041] ρ Β Density of the medium under operating conditions;

[0042] d P It represents differential pressure.

[0043] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0044] This invention can solve problems such as gas and liquid two-phase flow measurement and accurate measurement of sulfur-containing gas field water under two conditions: corrosive components (especially sulfur-containing components), non-full pipe flow, and liquid phase flow rate.

[0045] This invention addresses the situation where the liquid phase dominates in a gas-liquid mixture present in a pipeline. By measuring the mixing ratio of liquid and gas in real time and obtaining information such as temperature and liquid level, and by calculating and correcting the data, the real-time production of water and gas in the oil and gas well is calculated separately. Attached Figure Description

[0046] Figure 1 This is a schematic diagram of the structure of the present invention;

[0047] The components include: 1. Differential pressure flow meter one; 2. Differential pressure flow meter two; 3. Probe one; 4. Probe two; 5. Multi-parameter transmitter; 6. Liquid level differential pressure transmitter; 10. Pipeline. Detailed Implementation

[0048] In this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," "linking," "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. The terms "first," "second," and similar terms used in this application do not indicate any order, quantity, or importance, but are merely used to distinguish different components. Similarly, "a" or "one," etc., do not indicate a quantity limitation, but rather indicate the existence of at least one. In the implementation of this application, "and / or" describes the association relationship of related objects, indicating that three relationships can exist. For example, A and / or B can represent: A existing alone, A and B existing simultaneously, or B existing alone. In the description of the embodiments of this application, unless otherwise stated, "multiple" means two or more. For example, multiple positioning posts refer to two or more positioning posts. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0049] The present invention will now be described in detail.

[0050] like Figure 1 As shown, a two-phase flow measuring device for oil and gas field water corrosion resistance is used for measuring gas field water in pipeline 10 and is used in conjunction with a flow totalizer. It includes a differential pressure flow meter 1 for measuring the mass flow rate of gas in pipeline 10, a differential pressure flow meter 2 for measuring the mass flow rate of liquid in pipeline 10, a temperature sensor for measuring the temperature of gas in pipeline 10, and a liquid level differential pressure transmitter 6 for measuring the liquid level in pipeline 10.

[0051] Specifically, the differential pressure flow meter 1, differential pressure flow meter 2, and temperature sensor are connected to the flow totalizer via the multi-parameter transmitter 5, and the liquid level differential pressure transmitter 6 is connected to the flow totalizer; the multi-parameter transmitter 6 measures the differential pressure value as B, where 2Pa≤B≤40kPa.

[0052] The present invention will be installed in the horizontal section of pipeline 10;

[0053] The present invention obtains the gas mass flow rate by measuring the gas mass flow rate by differential pressure flow meter 1, obtains the liquid mass flow rate by measuring the liquid mass flow rate by differential pressure flow meter 2, and calculates the duty cycle by combining the liquid level information monitored by the liquid level differential pressure transmitter 6; thereby calculating the instantaneous liquid flow rate, instantaneous gas flow rate, cumulative liquid flow rate, and cumulative gas flow rate.

[0054] In some possible implementations, the pipeline 10 is in a gas-liquid mixed state during actual use, and the liquid surface boundary may not be clear. In order to achieve the best measurement effect, the flow field needs to be tuned. In this regard, the present invention also includes a gas-liquid diversion device installed in the pipeline 10 and located in the input section of the pipeline 10.

[0055] It also includes a drain outlet installed on pipeline 10 for discharging solid impurities separated by the gas-liquid separation device.

[0056] A gas-liquid splitting device is installed at the inlet of pipeline 10 to keep the gas and liquid phases relatively independent with a clear interface. When the interface is between differential pressure flowmeter 1 and differential pressure flowmeter 2, the entire flow measurement device can work stably. When the interface is higher than differential pressure flowmeter 1 or lower than differential pressure flowmeter 2, differential pressure flowmeter 1 or differential pressure flowmeter 2 will give an alarm signal, that is, the accurate two-phase flow cannot be measured.

[0057] Since the two-phase medium entering the measuring tube also contains a certain amount of solid impurities such as sand and gravel, if sand and gravel enter the probe or accumulate excessively at the probe, it will affect the flow measurement or damage the probe rods (probe rod 1, 3 and 4). The gas-liquid separation device will cause the suspended sand and gravel to settle at the bottom of the pipeline 10, minimizing its entry into the probe rods (probe rod 1, 3 and 4), effectively preventing damage to the probe rods (probe rod 1, 3 and 4) and extending the maintenance cycle. When the amount of sand and gravel deposited in the pipeline 10 reaches a certain level, the sand and gravel can be discharged through the drain outlet, avoiding production shutdown for maintenance.

[0058] When a natural gas well is producing, the gas field water undergoes gas-liquid-solid separation via a desanding skid and a gas-liquid separation device. Solid impurities are discharged through a drain outlet and enter the gas field water drainage pipeline 10. When the medium (gas or liquid) flows through the probe rod 3 or 4 that extends into the pipeline, a pressure difference is generated at both ends of the probe rod 3 or 4. The differential pressure is measured by differential pressure flow meter 1 and differential pressure flow meter 2, respectively. At the same time, the liquid level differential pressure transmitter 6 determines the liquid level height by measuring the difference between the bottom pressure and the top pressure.

[0059] In some possible implementations, the differential pressure flow meter 1 and the differential pressure flow meter 2 have the same structure and are both deltabar flow meters, with pressure tapping holes provided on their probe rods 3 and 4.

[0060] Both differential pressure flowmeter 1 and differential pressure flowmeter 2 are provided with a high-pressure chamber and a low-pressure chamber, wherein the high-pressure chamber is located on the flow-facing side of pipeline 10 and the low-pressure chamber is located on the flow-returning side of pipeline 10.

[0061] The low-pressure sides of differential pressure flowmeter 1 and differential pressure flowmeter 2 are respectively connected to the differential pressure transmitter via pressure taps.

[0062] The Delta bar flow meter used in this invention is existing technology and its internal structure will not be described in detail here.

[0063] When the medium flows through the probe (probe 3 or probe 4), a pressure difference is generated at both ends of the probe (probe 3 or probe 4). This pressure difference is proportional to the flow rate. By taking pressure samples at the high-pressure end and the low-pressure end using probe 3 and probe 4 respectively, and measuring the differential pressure using differential pressure flowmeter 1 and differential pressure flowmeter 2, the gas mass flow rate and liquid mass flow rate can be calculated based on the differential pressure value.

[0064] In some possible implementations, the probe 3 of the differential pressure flow meter 1 extends vertically into the pipeline 10 through the top of the pipeline 10 and its end does not contact the liquid.

[0065] The probe 4 of the differential pressure flow meter 2 extends vertically into the pipeline 10 through the bottom of the pipeline 10, and its end does not contact the gas.

[0066] Furthermore, the probes (probe 1 3 and probe 2 4) are made of 1.4571 stainless steel, which is austenitic stainless steel. It has good corrosion resistance and wear resistance, which can effectively avoid corrosion by the medium and wear by solid particles.

[0067] The process adopts one-piece molding, and the entire probe (probe 1-3 or probe 2-4) has no weld seams, which completely avoids the problem of insufficient corrosion resistance of weld seams;

[0068] The probe (probe 3 or probe 4) is perpendicular to the horizontal section of pipeline 10 and is set vertically. It adopts a vertical insertion method to effectively realize the differential pressure of gas by probe 3 of differential pressure flow meter 1 and the differential pressure of liquid by probe 4 of differential pressure flow meter 2.

[0069] In some possible implementations, when the diameter of pipeline 10 is A, and when A ≤ DN65; the pressure taps are in a set.

[0070] When DN80≤A≤DN300, there are two sets of pressure taps;

[0071] When A > DN300, there are three sets of pressure taps;

[0072] Specifically, when there are multiple sets of pressure taps, they are set along the axial direction of the probe rods (probe rod 3 or probe rod 4).

[0073] A measurement method for a two-phase flow measuring device for oil and gas field water corrosion resistance, as described above, specifically includes the following steps:

[0074] The horizontal section of pipeline 10 is directly connected to the oil and gas well sewage pipeline 10. When the natural gas well is producing, the gas field water enters the gas field water sewage pipeline 10 after gas-liquid solid-solid separation through the desanding skid and gas-liquid separation device (solid impurities are discharged through the sewage outlet). The gas-liquid separation device keeps the gas and liquid phases relatively independent and has a clear interface. When the medium (gas or liquid) flows through probe rod 1 3 and probe rod 2 4, a pressure difference will be generated at both ends of probe rod 1 3 and probe rod 2 4. This differential pressure is measured by differential pressure flow meter 1 and differential pressure flow meter 2.

[0075] The multi-parameter transmitter 5 transmits temperature information, and the differential pressure information from differential pressure flow meter 1 and differential pressure flow meter 2 is transmitted to the flow totalizer.

[0076] The liquid level differential pressure transmitter 6 measures the liquid level information and transmits it to the flow totalizer to obtain the instantaneous gas flow rate and the instantaneous liquid flow rate data. The data is then transmitted to the host computer system for final production management evaluation.

[0077] Specifically, temperature information will be used to correct data when the flow totalizer performs calculations;

[0078] The flow totalizer calculates the instantaneous flow rate of gas and liquid based on the data provided by the multi-parameter transmitter 5 and the liquid level differential pressure transmitter 6. The flow totalizer can not only display the current flow rate value in real time, but also has an accumulation function, which can accumulate the flow rate over a period of time. By accumulating the flow rate, the total amount of fluid in a certain period of time can be obtained, such as the accumulated volume or accumulated mass, which can be queried.

[0079] Specifically, the formula for calculating the gas mass flow rate or liquid mass flow rate is as follows:

[0080]

[0081] Where, q m Let be the mass flow rate, where the gas mass flow rate is q. ma The mass flow rate of the liquid is q mb ;

[0082] ζ is the blocking coefficient of the probe;

[0083] ε is the flow expansion coefficient;

[0084] d is the inner diameter of the pipe;

[0085] ρ Β Density of the medium under operating conditions;

[0086] d P Differential pressure;

[0087] Calculate the instantaneous gas flow rate = q ma ×(1-C);

[0088] Calculate the instantaneous flow rate of the liquid = q mb ×C;

[0089] Calculate the liquid duty cycle C based on the liquid level information provided by the liquid level differential pressure transmitter 6;

[0090]

[0091] Among them, S 液 S is the cross-sectional area of ​​the liquid. 管 The cross-sectional area of ​​the pipeline is 10.

[0092] Specifically, S 管 =π×r 2 ;

[0093] S 液 =π×r×acos[(rh) / r]×57.29578 / 180-(rh)×sqrt[r-(rh)];

[0094] h is the liquid level; r is the radius of the pipeline;

[0095] Instantaneous gas flow rate is calculated based on gas mass flow rate and duty cycle;

[0096] Instantaneous flow rate of liquid is calculated based on liquid mass flow rate and duty cycle.

[0097] In some possible implementations, the formula for calculating the gas mass flow rate or liquid mass flow rate is:

[0098] Where, q m Let be the mass flow rate, where the gas mass flow rate is q. ma The mass flow rate of the liquid is q mb ;

[0099] ζ is the blocking coefficient of the probe;

[0100] ε is the flow expansion coefficient;

[0101] d is the inner diameter of the pipe;

[0102] ρ Β Density of the medium under operating conditions;

[0103] d P Differential pressure;

[0104] Calculate the instantaneous gas flow rate = q ma ×(1-C);

[0105] Calculate the instantaneous flow rate of the liquid = q mb ×C;

[0106] Where, q ma Let q be the gas mass flow rate. mb This represents the liquid mass flow rate.

[0107] It should be noted that before production, the differential pressure flow meter 1, differential pressure flow meter 2, multi-parameter transmitter 5, liquid level differential pressure transmitter 6, and flow totalizer need to be calibrated.

[0108] Furthermore, the cumulative gas flow rate can be calculated based on the instantaneous gas flow rate, and the cumulative liquid flow rate can be calculated based on the instantaneous liquid flow rate.

[0109] The flow totalizer can query the cumulative flow of liquids and gases by year, month, and day. When different dates are selected, it will automatically display the cumulative flow of gas and liquid for the current query time. It can also query the instantaneous flow of liquids, instantaneous flow of gas, and duty cycle of liquids. It also has storage and dump functions.

[0110] This invention is not limited to the specific embodiments described above. The invention extends to any new feature or combination disclosed in this specification, as well as any new method or process step or combination disclosed herein.

Claims

1. A two-phase flow measuring device resistant to corrosion from water in oil and gas fields, used for measuring water in oil and gas fields within pipelines and in conjunction with a flow totalizer, characterized in that, It includes a differential pressure flow meter 1 for measuring the mass flow rate of gas in the pipeline, a differential pressure flow meter 2 for measuring the mass flow rate of liquid in the pipeline, a temperature sensor for measuring the temperature of gas in the pipeline, and a liquid level differential pressure transmitter for measuring the liquid level in the pipeline; the temperature sensor, differential pressure flow meter 1, differential pressure flow meter 2, and liquid level differential pressure transmitter are respectively connected to a flow totalizer.

2. The two-phase flow measuring device for oil and gas field water corrosion resistance according to claim 1, characterized in that, It also includes a gas-liquid separation device installed inside the pipeline and located in the pipeline inlet section.

3. The two-phase flow measuring device and method for oil and gas field water corrosion resistance according to claim 2, characterized in that, It also includes a drain outlet installed on the pipeline for discharging solid impurities separated by the gas-liquid separation device.

4. The two-phase flow measuring device and method for oil and gas field water corrosion resistance according to claim 1, characterized in that, The differential pressure flow meter one and differential pressure flow meter two have the same structure and are both deltabar flow meters, with pressure tapping holes provided on their probes; Both differential pressure flowmeter one and differential pressure flowmeter two are provided with a high-pressure chamber and a low-pressure chamber, wherein the high-pressure chamber is located on the flow-facing side of the pipeline and the low-pressure chamber is located on the flow-reverse side of the pipeline. The low-pressure sides of differential pressure flowmeter one and differential pressure flowmeter two are respectively connected to the differential pressure transmitter through pressure taps.

5. A two-phase flow measuring device for oil and gas field water corrosion resistance according to claim 4, characterized in that, The probe of the differential pressure flow meter extends vertically into the pipeline through the top of the pipeline and its end does not contact the liquid. The probe of the differential pressure flowmeter II extends vertically into the pipeline through the bottom of the pipeline, and its end does not contact the gas.

6. A two-phase flow measuring device for oil and gas field water corrosion resistance according to claim 4, characterized in that, When the diameter of the pipeline is A, and A≤DN65; the pressure taps are a set; When DN80≤A≤DN300, there are two sets of pressure taps; When A > DN300, there are three sets of pressure taps.

7. A two-phase flow measuring device for oil and gas field water corrosion resistance according to claim 4, characterized in that, It also includes a multi-parameter transmitter connected to differential pressure flow meter 1, differential pressure flow meter 2, temperature sensor, and flow totalizer respectively. The measured differential pressure value of the multi-parameter transmitter is B, where 2Pa≤B≤40kPa.

8. A measurement method for a two-phase flow measuring device for oil and gas field water corrosion resistance according to any one of claims 1-7, characterized in that, Specifically, the following steps are included: The gas-liquid separator keeps the gas and liquid phases relatively independent, with a clear interface. The gas mass flow rate and liquid mass flow rate are calculated based on differential pressure flow meter 1 and differential pressure flow meter 2. Calculate the liquid duty cycle C based on the liquid level information provided by the differential pressure level transmitter; Among them, S 液 S is the cross-sectional area of ​​the liquid. 管 This refers to the cross-sectional area of ​​the pipeline. Instantaneous gas flow rate is calculated based on gas mass flow rate and duty cycle; Instantaneous flow rate of liquid is calculated based on liquid mass flow rate and duty cycle.

9. A two-phase flow measurement method for oil and gas field water corrosion resistance according to claim 8, characterized in that, Instantaneous gas flow rate = q ma ×(1-C); Instantaneous flow rate of liquid = q mb ×C; Where, q ma Let q be the gas mass flow rate. mb This represents the liquid mass flow rate.

10. A two-phase flow measuring device and method for resisting water corrosion in oil and gas fields according to claim 8, characterized in that, The formula for calculating the gas mass flow rate or liquid mass flow rate is as follows: Where, q m For mass flow rate; ζ is the blocking coefficient of the probe; ε is the flow expansion coefficient; d is the inner diameter of the pipe; ρ Β Density of the medium under operating conditions; d P It represents differential pressure.

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